ML12221A357
| ML12221A357 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 07/27/2012 |
| From: | Allegheny Electric Cooperative |
| To: | Office of Nuclear Reactor Regulation |
| References | |
| Download: ML12221A357 (18) | |
Text
[NOTE 5-7] NUCLEAR DECOMMISSIONING TRUST The Nuclear Decommissioning Trust consists of the following as of December 31, 2011 and 2010:
2011 Gross Gross Unrealized Unrealized Realized Fair Cost Gains Losses Losses Value (In thousands)
Decommissioning Trust Fund Money market funds $460 $460 U.S. Government securities 23,584 1,398 (9) 24,973 Corporate bonds 13,172 713 (120) 13,765 Other obligations 1,864 120 (2) 1,982 Common stocks 27,798 11,577 (336) (722) 38,317 Total $66,878 $13,808 $(467) $(722) $ 79,497 2010 Gross Gross Unrealized Unrealized Realized Fair Cost Gains Losses Losses Value (In thousands)
Decommissioning Trust Fund Money market funds $1,203 $1,203 U.S. Government securities 21,625 135 (338) 21,422 Corporate bonds 12,818 627 (98) 13,347 Other obligations 1,076 42 (14) 1,104 Common stocks 24,364 11,812 (172) 36,004 Total $61,086 $12,616 $ (622) . $ 73,080 The trust has a concentration in U.S. treasury notes and bonds, which were approximately $24 million and $20 million in 2011 and 2010, respectively.
Certain investments indebt and equity securities are reported inthe financial statements at an amount less than their historical cost. Total fair value of these investments at December 31, 2011 and 2010, was
$14 million and $21.4 million, respectively. These declines primarily resulted from increases in market interest rates prior to the balance sheet date and the failure of certain investments to meet projected earnings targets. The gross unrealized losses at December 31, 2011 for a period of less than 12 months were $1,007,000 and for a period of ANNUAL REPORT 2011
greater than 12 months were $183,000. The gross unrealized losses at December 31, 2010 for a period of less than 12 months were $549,000 and for a period of greater than 12 months were $73,000.
For 2011, the Cooperative recorded other-than-temporary impairments on equity securities inthe amount of
$722,000. The cost-basis of these investments has been adjusted to reflect the recognition of these impairments.
No other-than-temporary impairment was recorded for 2010.
Under ASC Topic 980, Regulated Operations,the Cooperative has elected to defer these losses and pass them on to members through the future rate structure. As of December 31, 2011 and 2010, total deferred charges for the Nuclear Decommissioning Trust other-than-temporary impairment were $3,869,000 and $3,315,000.
I NOTE DERIVATIVES AND HEDGING The Cooperative does not engage in speculative derivative transactions, however, the Cooperative engages in hedging activities that are a natural part of power supply and transmission activities.
The Cooperative uses hedging instruments, including forwards, futures, financial transmission rights, and options, to manage power market price risks. Inaddition, substantial reliance on the purchase of energy from other power suppliers exposes the Cooperative to the risk that counterparties will default. Therefore, an assessment is performed on the creditworthiness of counterparties and other credit issues related to these purchases, which may require the counterparties to post collateral. Defaults, however, may still occur. Ifa default occurs, the Cooperative may be forced to enter into alternative contractual arrangements or purchase energy in the forward, short-term or spot markets at then-current market prices that could vary from the prices previously agreed upon with the defaulting counterparty. The Cooperative has never had a counterparty default or fail to perform, but past performance is no guarantee of future results.
Financial Transmission Rights The Cooperative is issued Financial Transmission Rights (FTRs) by the PJM Interconnection LLC, (PJM). These FTRs have been found to meet the FASB ASC Topic 815, Derivatives and Hedging, definition of a derivative, and therefore must have special derivative accounting procedures applied to them.
The Cooperative receives an entitlement of FTRs. FTRs are defined from a "source" node to a "sink" node (path) for a specific amount of megawatts of electric power. The holder of an FTR is entitled to receive whole or partial offsets of transmission congestion charges that arise when that specific path is congested. The purpose of the FTR mechanism is to act as a hedge against volatile congestion charges.
Market values of FTRs are only observable based on the clearing prices of the FTRs in multi-year, annual, seasonal and monthly auctions. The expected value of FTRs fluctuates based on seasonal expectations of the supply and demand of energy for each specific path. Significant assumptions and modeling projections are necessary to value FTRs. The expected FTR values are considered in the rate-making process and therefore the fair value of FTRs are recognized on the balance sheet and recorded as deferred income under ASC Topic 980, Regulated Operations.The fair value of FTRs was $10,242,000 and $13,030,000 as of December 31, 2011 and 2010 for the remainder of the current PJM planning periods that end May 31, 2011 and 2010 and beyond.
2011 2010 (Inthousands)
Fair value of FTRs $10,242 $13,030 Balance sheet locations Current assets Current assets Current liabilities Current liabilities Noncurrent assets Noncurrent assets Noncurrent liabilities Noncurrent liabilities ALLEGHENY ELECTRIC COOPERATIVE, INC._
Forward Swaps The Cooperative is exposed to market purchases of power and natural gas to meet the power supply needs of the member distribution cooperatives that are not met by Cooperative owned generation. While the Cooperative does not engage in speculative practices, the Cooperative utilizes derivative contracts to manage this exposure. Power is purchased under both long-term and short-term physically-delivered and financially-settled forward contracts to supply power to member cooperatives. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of the forward purchase derivative contracts qualify for the normal purchases/
normal sales exception under previously issued guidance. As a result, these contracts are not recorded at fair value and are not subject to the disclosure requirements. Purchased power is expensed when the power under the forward contract is delivered.
The Cooperative purchases natural gas futures contracts to hedge the price of natural gas for use as a basis in determining the price of power in certain forward power purchase agreements. The Cooperative also purchases capacity swap forward contracts in order to lock in capacity pricing prior to the completion of capacity auctions.
These derivatives do not qualify for the normal purchases/normal sales exception; however, the Cooperative has opted out of the cash flow hedge accounting as allowed under previously issued guidance. For these derivative contracts that do not qualify for the normal purchases/normal sales exception, the Cooperative defers all gains and losses on a net basis as a regulatory asset or liability in accordance with ASC Topic 980, Regulated Operations.These amounts are subsequently reclassified as purchased power in the consolidated statements of margin as the power is delivered and/or the contract settles.
Generally, derivatives are reported on the consolidated balance sheet at fair value. The measurement of fair value is based on actively quoted market prices, ifavailable. Otherwise, indicative price information is sought from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contract's estimated fair value.
Changes inthe fair value of the derivative instruments are recorded as a regulatory asset or regulatory liability.
The change inthese accounts is included inthe operating section of the statement of cash flows.
As of December 31, 2011 and 2010, the Cooperative had the following outstanding derivative futures contracts:
Unit of Quantity Commodity Measure 2011 2010 Natural gas MMBTU - 30,000 Capacity swap MW 47,565 197,585 As of December 31, 2011 and 2010, the fair value of the derivative instruments, excluding contracts accounted for as a normal purchase/normal sale, were as follows:
2011 Remaining Cost Fair Value (inthousands) (inthousands)
Capacity swap forward contracts $ 9,097 $ 5,266 Balance sheet locations Current liabilities Current assets ANNUAL REPORT 2011
2010 Remaining Cost Fair Value (in thousands) (inthousands)
Natural gas futures contracts $157 $91 Capacity swap forward contracts 34,464 27,643 Total $ 34,621 $ 27,734 Balance sheet locations Current liabilities Current assets Noncurrent liabilities Noncurrent assets As of December 31, 2011 and 2010, the Cooperative has deferred the following losses on a net basis as a regulatory asset in accordance with ASC Topic 980, Regulated Operations.
Location of Loss in the Amount of Deferred Loss Statement of Margin at December31, 2011 at Settlement (Wm thousands)
Capacity swap forward contracts Purchased Power $ (3,2)
Location of Loss in the Amount of Deferred Loss Statement of Margin at December31,2010 at Settlement (in thousands)
Natural gas futures contracts Purchased Power $ (65)
Capacity swap forward contracts Purchased Power (6,821)
Total $ (6,M86)
NOTE 7: 1 DEFERRED CHARGES Deferred charges consist of the following regulatory assets as of December 31, 2011 and 2010.
2011 2010 (Inthousands)
Capital retirement asset $957 Deferred asset plan - NDT investments 3,869 3,315 Deferred asset plan - forward swaps 3,832 6,886 Safe harbor lease closing costs 13 25
$7,714 $11,183 Based on agreements signed by the 14 member distribution cooperatives on March 29, 1999, with an effective date of January 1, 1999, and amended in 2004 and 2006, a portion of the SSES impairment writedown that took place in 1998 has been recognized as a regulatory asset and is referred to as the capital retirement asset.
Under these agreements, the Cooperative was to recover from members certain financing costs related primarily to the Cooperative's investment in SSES in the amount of $311 million no later than December 31, 2009. During 2009, certain members elected to extend repayment under these agreements to 2011. During 2011, all remaining member repayments were received and the regulatory asset fully amortized.
ALLEGHENY ELECTRIC COOPERATIVE, INC.
I
NOTE 8: ASSET RETIREMENT OBLIGATION Amounts collected from the Cooperative's members for decommissioning, less applicable taxes, are deposited in external trust funds for investment and can only be used for future decommissioning costs. The fair value of the nuclear decommissioning trust was $79.5 million and $73.1 million for the years ended December 31, 2011 and 2010, respectively.
The changes inthe carrying amounts of asset retirement obligations were as follows:
2011 2010 (Inthousands)
Beginning balance $142355 $136,880 Accretion expense 5,695 5,475 Ending balance $148,050A $43 The amount of actual obligation could differ materially the estia reflected intial statements
I NOTE LONG-TERM DEBT 2011 2010 (inthousands)
Note payable CFC, payable in varying quarterly installments beginning April 2008, plus interest at 6.8%, final payment January 2014 $ 9,050 $12,775 Note payable CFC, payable in varying quarterly installments beginning April 2014, plus interest at 6.9%, final payment January 2021 38,600 38,600 Note payable CFC, payable in varying quarterly installments beginning April 2021, plus interest at 7.0%, final payment April 2025 39,700 39,700 Note payable CFC, payable in varying quarterly installments beginning July 2006, plus interest at 6.8%, final payment January 2014 1,350 1,925 Note payable CFC, payable in varying quarterly installments beginning April 2014, plus interest at 6.9%, final payment January 2021 5,800 5,800 Note payable CFC, payable invarying quarterly installments beginning April 2021, plus interest at 7.0%, final payment April 2025 6,200 6,200 Note payable CFC, payable invarying quarterly installments beginning July 2006, plus interest at 7.25%, final payment October 2025 12,026 12,507 Note payable CFC, payable invarying quarterly installments beginning July 2006, plus interest at 7.25%, final payment October 2025 1,924 2,002 Note payable CFC, payable invarying quarterly installments beginning October 2009, plus interest ranging from 4.05%
to 6.65%, final payment October 2025 37,667 38,750 Note payable CFC, payable invarying quarterly installments beginning January 2012, plus interest ranging from 2.90%
to 5.25%, final payment October 2025 10,000 Note payable CoBank, payable invarying annual installments beginning January 2012, plus interest ranging from 1.78%
to 4.89%, final payment January 2018 9,966 _
Total long-term debt 172,283 158,259 Less current installments 7,164 5,858 Long-term debt, net of current installments $165,119 $152,401 The Cooperative has an additional available borrowing balance with CFC through December 2025 beyond the operating line of credit below totaling $96,338,000 at December 31, 2011.
The Cooperative had a $35,000,000 operating line of credit with CFC that expired on March 31, 2011.
ALLEGHENY ELECTRIC COOPERATIVE, INC.
The Cooperative renewed the operating line of credit through March 31, 2016 at $50,000,000 under the same basic terms. There were no outstanding borrowings against this line as of December 31, 2011 and 2010.
The interest rate on the line of credit fluctuates as established by CFC.
Additionally, the Cooperative has a commitment from CFC to provide unsecured letters of credit of up to $25,000,000. Under this commitment, the Cooperative has unsecured letter of credit facilities totaling $16,600,000 which expire at various dates throughout 2012.
As of December 31, 2011 and 2010, no funds have been drawn against this facility.
Future maturities of all long-term debt are as follows (inthousands):
2012 $7,164 2013 7,721 2014 8,577 2015 9,140 2016 10,556 Thereafter 129,125
$172,283 The Cooperative is required to maintain certain covenants including an annual debt service coverage ratio. The Cooperative was incompliance with the applicable covenant as of December 31, 2011 and 2010, respectively.
During 2011 and 2010, the Cooperative incurred interest costs of $10,445,000 and $10,467,000, respectively.
NOTE 10.] INCOME TAXES As of December 31, 2011 and 2010, the Cooperative had available nonmember net operating loss carryforwards of approximately $13 million and $22 million, respectively for tax reporting purposes expiring in 2012 through 2019, and alternative minimum tax credit carryforwards of approximately $1,297,000 and $1,008,000 respectively, which carry forward indefinitely.
There was no provision for federal income taxes at December 31, 2011 and 2010. The Cooperative is not subject to state income taxes. The Cooperative is no longer subject to federal income tax examinations by tax authorities for years before 2008.
Temporary differences that give rise to deferred tax balances are principally attributable to fixed asset basis, safe harbor lease treatment, and financial statement accruals. Deferred tax assets also include the effect of net operating loss carryforwards. The temporary differences and the carryforward items produce a deferred tax asset at December 31, 2011 and 2010, of approximately $10.4 million and $18.0 million, respectively. Realization of the net deferred tax asset is contingent upon the Cooperative's future earnings. Avaluation allowance of approximately $1 million and $5 million in 2011 and 2010, respectively, has been established against this asset because it has been determined that this portion of the deferred tax asset more likely than not will be unrealized.
The Cooperative will include the utilization of the net deferred tax asset of approximately $9.4 million and $13.0 million at December 31, 2011 and 2010, respectively, infuture rates charged to members. Therefore, a deferred credit has been recorded equal to the net deferred tax asset under FASB ASC Topic 980, Regulated Operations.
ANNUAL REPORT 2011
I I NOTE 11:1 RELATED PARTY TRANSACTION Arelated organization, the Pennsylvania Rural Electric Association (PREA) has provided the Cooperative with certain management, general, and administrative services on a cost reimbursement basis. The costs for services provided by PREA were $946,000 and $891,000 for the years ended December 31, 2011 and 2010, respectively.
I NOTE 12:j CONSOLIDATED VARIABLE INTEREST ENTITY As the primary beneficiary, the Cooperative consolidates CCS. The general creditors of CCS have no recourse against the general credit of the Cooperative.
The following table summarizes the carrying amount of the assets and liabilities of CCS included inthe Cooperative's consolidated balance sheets at December 31, 2011 and 2010:
2011 2010 (Inthousands)
Current assets Cash and cash equivalents $860 $543 Accounts receivable, affiliated organization 14 174 Other receivables 9 10 Other current assets 1,139 755 Non-utility property 15 21 Total assets $2,037 $1,503 Current liabilities Accounts payable and accrued expenses $1,488 $1,996 Accrued postretirement benefit cost 311 216 Accounts payable, affiliated organization 88 88 Total liabilities $1,887 $2,300 NOTE 13: POSTRETIREMENT BENEFITS During 2010, the administration of the postretirement benefit plan, including the obligation liability and all accounting for it,was transferred from PREA to CCS. As of November 1, 1995 (the effective date), PREA eliminated postretirement medical benefits to all of its employees except for grandfathered employees. There were two different levels of benefits for those grandfathered retirees. For each retiree over the age of 62 on the effective date, PREA, and now CCS, pays the full premium for the appropriate medical insurance for the covered participant. For those that were over the age of 55 but younger than 62 on the effective date, PREA, and now CCS, pays a maximum premium for medical insurance equal to the policy premium on November 1, 1995. Inthis second group, the participant is responsible for any increases above this amount. On December 31, 2011 and 2010, there were thirteen retirees or spouses covered under this plan. CCS expects to contribute $22,000 to the plan in 2012. This amount will be allocated to the Cooperative and PREA based on historical payroll allocations of the retirees covered under the plan.
ALLEGHENY ELECTRIC COOPERATIVE, INC.
CCS uses a December 31 measurement date for the plan. Information about the plan's funded status follows:
2011 2010 (In thousands)
Benefit obligation, projected $ 311 $216 Fair value of plan assets Funded status $ (311]) $(216)
Amounts recognized inthe statements of financial position:
2011 2010 (In thousands)
Accrued postretirement benefit cost liability $311 $216 Amounts recognized inaccumulated other comprehensive income not yet recognized as components of net periodic benefit cost consist of:
2011 2010 (In thousands)
Net loss $124 $ 30 Transition obligation 65 82
$189 $112 The accumulated benefit obligation for the plan was $122,000 and $104,000 at December 31, 2011 and 2010, respectively.
Other significant balances and costs are:
2011 2010 (In thousands)
Employer contributions $ 22 $6 Benefits paid 22 6 Benefit cost 54 9 The following amounts have been recognized in the consolidated statement of margins for the year ended December 31, 2011:
2011 2010 (In thousands)
Amounts arising during the period:
Net loss $94 Net transition obligation 17 17 ANNUAL REPORT 20111
The estimated net loss and transition obligation for the plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $8,000 and $17,000, respectively.
The discount rate used to determine the benefit obligation was 4.70% and 5.75% for 2011 and 2010, respectively.
For measurement purposes, a 6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2011 and should remain at that level.
As of December 31, 2011, the expected future payments (inthousands), which reflect expected future service, are as follows:
2012 $22 2013 22 2014 22 2015 21 2016 and thereafter 224 I NOTE 14: 1 EMPLOYEE BENEFIT PLANS All employment relationships are through CCS, the consolidated variable interest entity of the Cooperative. CCS's leave policies provide for payment of unused leave after the end of each calendar year for 2011 and 2010. A provision has been recorded for this liability.
The Cooperative through CCS, participates ina multi-employer defined-benefit pension plan and a 401(k) defined-contribution plan (Plans) covering substantially all of its employees. The Cooperative makes annual contributions to the Plans equal to the amount accrued for pension expense. Total pension expense for both plans approximated
$2,283,000 and $2,203,000 for the years ended December 31, 2011 and 2010, respectively.
The Cooperative, through CCS, has an employment agreement, that contains a funded deferred compensation agreement, with its President &CEO.
I NOTE 15: 1 COMMITMENTS AND CONTINGENCIES Power Supply and Transmission Agreements The Cooperative has entered into power supply and transmission agreements with various service providers. A significant number of these agreements are umbrella type agreements and do not bind the Cooperative to enter into any type of transaction.
Since June 2007, the Cooperative has issued periodic Requests for Proposal (RFP) for energy and/or capacity products for varying quantities and terms between one and five years with delivery beginning in 2009 or later.
As of December 31, 2011, there were several significant capacity and energy transactions under these umbrella agreements with some energy deliveries beginning as early as 2009 and extending through 2014.
The Cooperative also purchased capacity for 2009 through May 2015, in a series of transactions. These transactions contained specific quantities of capacity, all of which were or will be needed to serve the Cooperative's load.
Asummary of the power supply agreements are as follows:
New York Power Authority This contract meets a portion of the Cooperative's base load and peaking requirements and its delivered cost to the Cooperative's members is below market. The current contract terminates in 2025 for the Niagara Project.
The current contract for the St. Lawrence Project expires in2017.
ALLEGHENY ELECTRIC COOPERATIVE, INC.
2011 Energy Provider The Cooperative entered into an agreement in October 2009 to provide the Cooperative's remaining unmet load requirements beginning inJanuary 2010. The agreement requires the Cooperative to supply monthly a predetermined minimum amount of energy from its generation resources and power purchase agreements and purchase any remaining requirements to meet its load pursuant to the agreement. If it does not supply the minimum amount of generation required inany given month, the Cooperative is required to purchase replacement energy for any shortfalls at a market-based price. The transition to the new supplier occurred on January 1, 2010. On May 6, 2011, the Cooperative entered into an agreement with the supplier which modified the terms of the then current supply agreement. Under the new agreement the Cooperative reduced its expected cost of energy in return for assuming some market-based pricing risks for a portion of its needs. The agreement expired on December 31, 2011.
Future Power Supply Using the RFP process, the Cooperative entered into power purchase agreements in 2009 with various counterparties for a combination of around-the-clock, on-peak and off-peak energy and call option products that would meet approximately 90 percent of its projected energy requirements in 2012 and 2013. The Cooperative entered into an agreement in April 2011 to provide the Cooperative's remaining current load requirements beginning inJanuary 2012. The agreement expires in December 2012.
Various purchased power agreements require the Cooperative to post collateral deposits for exposure exceeding specified thresholds. As of December 31, 2011, collateral deposits totaled $417,000. Other agreements allow the Cooperative to provide additional credit support in the form of irrevocable standby letters of credit. The Cooperative had such letters issued as of December 31, 2011 inthe amount of $5,600,000. These letters of credit were provided by CFC and are valid through dates ranging from November 30, 2012 through December 31, 2012.
SSES Replacement Power Insurance Policy The Cooperative mitigated a portion of the economic risk of an outage at SSES by purchasing a Replacement Power Insurance Policy from Arrow Syndicate 1910. Under the terms of the policy, if SSES had a forced outage event, the Cooperative would have been reimbursed for the cost of replacement power for the insured quantity of up to 250 MW. The policy stipulates that the outage limit for each such forced outage is 90 consecutive days, and the aggregate coverage limit is $15 million. For this coverage, the Cooperative purchased a two-year policy terminating December 31, 2012.
Transmission Service Transmission service for the Cooperative's load is provided through a hybrid arrangement consisting of the PJM Open Access Transmission Tariff (OATT) and the pre-existing Wheeling and Supplemental Power Agreement with Pennsylvania Electric Company.
A separate irrevocable standby letter of credit is related to obligations existing under the OATT. This letter of credit was issued during 2011 in the amount of $11,000,000 to the benefit of PJM Settlement, Inc. The letter of credit was provided by CFC and is valid through August 14, 2012.
ANNUAL REPORT 2011
PPL, as the 90 percent owner and sole operator of SSES, and the Cooperative, as owner of a 10 percent undivided interest inSSES, are members of certain insurance programs which provide coverage for property damage to the SSES nuclear generation plant. Under these programs, the plant, as a whole, has property damage coverage for up to $2.75 billion. Additionally, there is coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions. Under the property and replacement power insurance programs, PPL and the Cooperative could be assessed retrospective premiums in the event the insurers' losses exceed their reserves. As of December 31, 2011, the maximum amount PPL and the Cooperative jointly could be assessed under these programs was $40 million annually.
PPL and the Cooperative's public liability for claims resulting from a nuclear incident is currently limited to
$12.6 billion under provisions of the Price-Anderson Act Amendments of 2005.
Inthe event of a nuclear incident at any of the reactors covered by the Act, PPL and the Cooperative could be assessed up to $235 million per incident, payable at $35 million per year.
Safe Harbor Lease The Cooperative previously sold certain investment and energy tax credits and depreciation deductions pursuant to a safe harbor lease. The proceeds from the sale, including interest earned thereon, have been deferred and are being recognized on the statements of operations over the 30-year term lease. The deferred gain was $0.3 million and $0.6 million as of December 31, 2011 and 2010, respectively.
Under the terms of the safe harbor lease, the Cooperative is contingently liable invarying amounts in the event the lessor's tax benefits are disallowed and inthe event of certain other occurrences. The maximum amount for which the Cooperative was contingently liable as of December 31, 2011 was approximately $1.7 million. Payment of this contingent liability has been guaranteed by CFC.
uLtaton The Cooperative may be subject to claims and lawsuits that arise primarily in the ordinary course of business.
At December 31, 2011, no such claims or lawsuits existed.
NOTE DEFERRED CREDITS Sale/Leaseback Arrangement The Cooperative previously completed a sale and leaseback of its hydroelectric generation facility at the Raystown Dam (the Facility). The Facility was sold to a trustee bank representing Ford Motor Credit Company (Ford) for $32 million in cash. During 1996, Ford transferred its interest in the Facility to a third party. Under terms of the arrangement, the Cooperative leased the Facility for an initial term of 30 years beginning June 1988.
Payments under the lease were due in semi-annual installments which commenced January 10, 1989. At the end of the 30-year term, the Cooperative had the option to purchase the Facility for an amount equal to the Facility's fair market value or for a certain amount fixed by the transaction documents.
The Cooperative also had the option to renew the lease for a five-year fixed rate renewal and three fair market renewal periods, each of which may not be for a term of less than two years. Payments during the fixed rate renewal period were 30 percent of the average semi-annual installments during the initial lease term. The lease payments were based on an assumed interest rate of 8.8 percent and Smay fluctuate based on differences between the future interest rate and the assumed interest rate.
Rental expense for this lease totaled $1.6 and $1.9 million in years ended December 31, 2011 and 2010,
_ALLEHENY ELECTRK COOPERATIVE, INC.
respectively. The Cooperative retained co-licensee status for the Facility throughout the term of the lease.
The gain of $1.9 million related to the sale was being recognized over the lease term. The unrecognized gain was recorded in other deferred revenue and was $632,000 as of December 31, 2010.
Effective October 27, 2011, the Cooperative executed an agreement to acquire the Facility. The remaining unrecognized gain of $566,000 was used to reduce the cost of the asset recorded.
Deferred Revenue Plan The Board has established a Deferred Revenue Plan, which seeks to stabilize members' rates for 2012 and as long as possible thereafter to mitigate the effects of expected increases in rates. The deferral of revenue for 2010 was determined as any amount above $500,000 operating margins. Deferred revenue additions and deletions are recorded in operating revenues inthe consolidated statements of margin. At December 31, 2011 and 2010, deferred revenues associated with the Deferred Revenue Plan were $10,428,000 and $35,732,000, respectively.
The changes in deferred revenues in 2011 and 2010 were as follows:
2011 2010 (Inthousands)
Beginning balance $ 35,732 $ 46,943 Additions - 3,079 Deletions (25,304) (14,290)
Ending balance $10,428 $ 35,732 Deferred Credit With the establishment of a deferred tax asset to record the effect of the temporary differences related to net operating loss carryforwards, fixed asset basis, safe harbor lease treatment, and financial statement accruals, the Cooperative established a deferred credit of $9.4 million and $13.0 million for 2011 and 2010, respectively, under FASB ASC Topic 980, Regulated Operations.The value of the deferred tax asset is considered inthe rate making process as required by Topic 980.
NOTE 17-, DISCLOSURES ABOUT FAIR VALUE OF ASSETS AND LIABILITIES ASC Topic 820, FairValue Measurements, defines fair value as the price that would be received to sell an asset or paid to transfer a liability inan orderly transaction between market participants at the measurement date. Topic 820 also specifies a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standard describes three levels of inputs that may be used to measure fair value:
Level 1 Quoted prices in active markets for identical assets or liabilities Level 2 Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in active markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities Level 3 Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities Following is a description of the valuation methodologies and inputs used for instruments measured at fair value on a recurring basis and recognized inthe accompanying balance sheet, as well as the general classification of such instruments pursuant to the valuation hierarchy.
ANNUAL REPORT 2011
Nuclear Decommissioning Trust and Investments (Available-for-sale Securities)
Where quoted market prices are available inan active market, securities are classified within Level 1 of the valuation hierarchy. Level 1 securities include highly liquid government bonds and exchange-traded equities. If quoted market prices are not available, then fair values are estimated by using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. For these investments, the inputs used by the pricing service to determine fair value may include, one, or a combination of: observable inputs such as benchmark yields, reported trades, broker/dealer quotes, benchmark securities, bids, offers, and reference data market research publications and are classified within Level 2 of the valuation hierarchy. Level 2 securities include certain collateralized mortgage and debt obligations and certain municipal securities. Incertain cases where Level 1 or Level 2 inputs are not available, securities are classified within Level 3 of the hierarchy and include auction rate securities. Inputs include quoted market prices, benchmark securities, bids, offers and broker/dealer quotes.
Derivatives The fair value is estimated using inputs that are observable or that can be corroborated by observable market data and, therefore, are classified within Level 2 of the valuation hierarchy. For financial transmission rights, inputs include clearing prices of the FTRs at multi-year, annual, seasonal and monthly auctions adjusted for seasonal expectations of the supply and demand of energy. For forward swaps, inputs include actively quoted market prices, broker quotes and industry publications.
The following table presents the fair value measurements of assets recognized inthe accompanying consolidated balance sheet measured at fair value on a recurring basis and the level within the fair value hierarchy inwhich the fair value measurements fall at December 31, 2011 and 2010:
2011 Fair Value Measurements Using Quoted Prices in Significant Active Markets Other Significant for Identical Observable Unobservable Fair Assets Inputs Inputs Value (Level 1) (Level 2) (Level 3)
(In thousands)
Available-for-sale securities Nuclear Decommissioning Trust $ 79,497 $62,420 $17,077 $-
Investments 45,264 3,980 38,203 3,081
2010 Fair Value Measurements Using Quoted Prices in Significant Active Markets Other Significant for Identical Observable Unobservable Fair Assets Inputs Inputs Value (Level 1) (Level 2) (Level 3)
(In thousands)
Available-for-sale securities Nuclear Decommissioning Trust $ 73,080 $ 56,970 $16,110 $-
Investments 54,667 4,733 46,656 3,278 Derivatives Financial transmission rights 13,030 - 13,030 Forward swaps 27,734 27,734 The following is a reconciliation of the beginning and ending balances of recurring fair value measurements recognized inthe accompanying balance sheet using significant unobservable (Level 3) inputs:
Debt Security (In thousands)
Balance, January 1, 2010 $3,578 Total realized and unrealized gains and losses Included innet margin Included inother comprehensive margin Settlements (300)
Transfers in and/or out of Level 3 Balance, December 31, 2010 3,278 Total realized and unrealized gains and losses Included in net margin 103 Included in other comprehensive margin Settlements (300)
Transfers in and/or out of Level 3 _
Balance, December 31, 2011 $3,081 During 2010, there were no realized gains and losses for the item reflected inthe table above included in net margin inthe accompanying consolidated statements of margin. During 2011, realized gains of $103,000 for the item reflected inthe table above is included in net margin inthe accompanying consolidated statements of margin.
The following methods were used to estimate the fair value of all other financial instruments not recognized inthe accompanying balance sheet.
Cash and Cash Equivalents The carrying amount approximates fair value.
ANNUAL REPORT 2011
Investments in Associated Organizations Management was not able to estimate the fair value of investments that represent the Cooperative's investment in memberships and other associated organizations and they remain at their carrying value.
Long-term Debt Due to the current market interest rates and/or short-term maturities of the Cooperative't debt, carrying amounts approximate fair value.
The estimated fair values of the Cooperative's financial instruments at December 31, 2011 and 2010 are as follows (inthousands):
2011 2010 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Cash and cash equivalents $16,067 $16,067 $31,888 $ 31,888 Investments 45,264 45,264 57,167 57,167 Nuclear Decommissioning Trust 79,497 79,497 73,080 73,080 Investment in associated organizations 27,490 27,490 27,556 27,556 Derivative investments 15,508 15,508 40,764 40,764 Long-term debt 172,283 172,283 158,259 158,259 rdlym. REALTY TAXES The Cooperative's portion of local real estate taxes related to SSES are billed by and paid to PPL. The Cooperative is billed and pays directly to various local tax jurisdictions local real estate taxes on other property that is exclusively owned by the Cooperative.
CURRENT ECONOMIC CONDITION The current protracted economic decline continues to present electric cooperatives with difficult circumstances and challenges, which in some cases have resulted in large and unanticipated declines in the fair value of investments and other assets. The financial statements have been prepared using values and information currently available to the Cooperative.
Current economic conditions have put additional pressure on many cooperatives and affiliated organizations to meet their financing and liquidity needs. A significant decline in operating revenues could have an adverse impact on the Cooperative's future operating results.
In addition, given the volatility of current economic conditions, the values of assets and liabilities recorded in the financial statements could change, resulting in material future adjustments in investment values, allowances for receivables, etc. All known impairments and changes to fair value have been recorded in these financial statements.
FSEM, SUBSEQUENT EVENTS Subsequent events have been evaluated through April 24, 2012, which is the date the financial statements were available to be issued.
ALLEGHENY ELECTRIC COOPERATIVE, INC.
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